There was an Explosion of Merchant Plant Project Announcements in 1998, and There are now More than 50,000 MW of merchant power in development or under construction in this country. Activity is concentrated in New England, followed by Texas and California. Other regions are seeing very little activity, although all regions project needs for more capacity (Table 1).
In New England, developers are planning more than 20,000 MW of capacity, mainly combined cycle. Much of the capacity will come on-line in the year 2000. The region has about 24,500 MW of generation resources after expected nuclear retirements. The peak demand is 22,000 MW, leaving a reserve margin of 11 percent. Only about 3,000 MW of additional capacity is needed in the next few years.
Developers seem to be counting on replacing high-cost oil/gas steam plants with combined-cycle units. But the oil/gas steam plants are only 16 percent of total capacity and produce only 21 percent of the region`s energy requirements. This is not economic justification for 20,000 MW of new plants (Figure 1).
In Texas, developers are planning more than 10,000 MW of new plants, mostly combined cycle or cogeneration. A large portion of this power is expected to be on-line in 2000, well exceeding the area`s demand. Texas has a 1998 margin of 17 percent and no urgent need for capacity. Developers are looking to replace existing gas-steam plants, which account for 26 percent of the region`s capacity, producing 30 percent of its energy requirements.
In California, plants totaling more than 8,000 MW are intended to replace some of the existing oil/gas steam plants, which are 32 percent of the region`s resources. On-line dates are mostly after 2001. California`s reserve margin is more than 25 percent, so the need for additional capacity is several years away.
The Midwest has projected reserve margins in the 14 to 16 percent range. There are nuclear plants off-line, limiting available capacity, and the region suffered a scare last summer. Additions in this region are mostly peaking plants planned by utilities as rate-based assets with regulators` approval.
The Southeast has reserve margins from 11 to 16 percent. This area is resisting deregulation and most developments are utility plants to meet capacity needs. Peaking plants predominate.
The merchant boom is driven by the structural changes in the industry. These changes have resulted in the separation of the traditional utility industry into separate companies for generation, transmission and distribution. The structural changes have resulted from the existence of high electricity prices and the disparity of price between adjacent utilities. The price differences have consequently resulted in state regulatory and legislative changes, and federal regulatory and proposed legislative changes.
Other significant factors driving these changes in the electric power industry include:
Large companies are the primary players in the merchant field. Large companies have several advantages, including the broad balance sheets needed to invest the large amounts of equity financing needed for merchant plants. Large firms also can diversify risks by owning a portfolio of different types of plants in different regions of the country. These large companies can hedge their risks through power marketing capabilities; several companies in the merchant plant market have significant power marketing capabilities.
These advantages have contributed to the ongoing stream of mergers and acquisitions among utilities. Mergers and acquisitions can provide economies of scale, improving competitiveness and increasing shareholder value. Fuel and energy companies that own merchant plants will be able to provide flexibility in fuel pricing and contracting strategies. Since most of the announced merchant plants are to be natural gas-fired, combined-cycle plants, gas company involvement in the ownership will have significant advantages.
A variety of factors will affect the likelihood of a merchant project finding financing. If part of the plant`s output is under contract, this guarantees an income stream. Most merchant plants currently being developed have partial power purchase agreements, selling a fraction of their electric capacity and/or steam to a nearby industrial site or a local utility.
Another element is the project`s perceived competitiveness. To obtain financing, a project must be one of the least-cost producers in the area. Understanding and forecasting market pricing is a critical skill for merchant power companies.
Several innovative financial enhancements are being used to aid in the search for financing. Methods to shift risk include subordinating fuel expenses to debt service payments or using a tolling agreement for fuel supply and power output. Methods to share risk include higher equity investments, limited parent guarantees, or subordinated debt provided by vendors and/or EPC contractors.
The face of power plant financing is changing. Most equity financing will be provided by a few companies with fat balance sheets. Financing will typically be limited recourse financing. The equity portion of the capital structure will be 35 to 50 percent depending on the project`s risk factors. Average debt coverage ratios will be 1.75 to 2.0, and debt terms will be 10 to 20 years. Other financial structural enhancements such as subdebt, limited parent guarantees and commodity swaps will become more common.
The merchant plants must sell their power at a rate sufficient to cover fuel costs, operating and maintenance costs, income and property taxes, debt service, working capital, and return on and recovery of the equity investment. This price is generally calculated at the busbar of the plant and may be separated into capacity and energy components. Economic analysis begins with a forecast of market prices for power. In a deregulated market, prices need to be forecast by time of day and time of year. Such forecasts can then be summed into a market price duration curve.
For a typical 500 MW natural gas-fired, combined-cycle merchant plant, fuel costs represent about 55 percent of the busbar costs in the first few years, with the fixed costs representing about 20 percent. Operating and maintenance costs represent about 15 percent of the busbar cost in the early years. Busbar cost varies according to variations in fuel price. A 25 percent decrease in fuel cost results in a 13 percent decrease in busbar cost. Site specific costs can vary widely.
In general, the merchant plants coming into service over the next five years are expected to generate power at a busbar price from 2.5 to 3.5 cents/kWh. These plants are expected to maintain their economic viability over their operating life.
Until recently, gas market forecasts did not account for the large amount of new gas-fired generation capacity that will enter the markets in the not-too-distant future. The merchant plants are counting on the continuing low price of natural gas, but the boom in demand may push up prices. When the full amount of new gas-fired capacity is considered, projected total gas demand is higher than previously anticipated, and new gas pipeline capacity is needed beyond what is planned. City-gate gas prices may rise to pay for the pipe, and wellhead gas prices may also rise. The costs of gas-fired generation on the margin will also increase. Despite the jump in price, natural gas will remain the fuel of choice for new generation (Table 2).
The gas industry is adapting to the changing market. As the gas and electric industries converge, several trends are beginning to emerge. Pipeline operators are partnering with power producers to build new pipelines and generation concurrently. By striking deals to build pipeline to the new plants in exchange for long-term transportation arrangements, gas flow is guaranteed and pipeline investments can be partially recovered.
The pipeline business is also devising new services and pricing, such as intra-day nominations and negotiated rate structures to accommodate rapidly changing hourly generation needs.
By the year 2000, there will be about 12.5 billion cubic feet per day of new pipeline capacity in the U.S. These proposed expansions generally fall into three groups-those bringing Alberta gas through Chicago and into the Northeast, pipelines accessing Eastern Canadian production, and new capacity for the Gulf Coast.
Following three major studies in the past year, consulting firm RDI has determined that the market pressure on natural gas prices will not be enough to give coal-fired generation the edge in new construction. The electric generation sector will continue to be the most important new market for natural gas in the next decade. The lower capital costs, reduced environmental impacts and modularity of gas capacity give it the advantage.
Gas demand for electric generation, including non-utility generation, will rise from about 4 trillion cubic feet (Tcf) in 1998 to 8.5 Tcf in 2010, an 8.8 percent annual growth. The residential and commercial gas demand is expected to grow at 1.7 percent. Industrial demand is expected to grow at 0.9 percent annually.
RDI predicts gas wellhead prices will be forced down in the near term due to supply and pipeline capacity increases from Canadian sources. Then as electric generation demand rises between 2001 and 2002, prices should rise, stimulating gas suppliers to invest in new productive capacity, tempering prices for the next few years.
Gas price increases, however, do not reduce the incentives for gas-fired merchant plants. The profit margins of new gas-fired plants will actually widen with higher gas prices, because higher gas prices raise the incremental operating costs of the older, higher heat rate gas-fired plants that determine market energy prices. The heat rate differential between new and existing generation becomes more valuable with higher gas prices. PE